In the power industry, electricity is produced with a spinning turbine that is turned at high speeds to generate electricity. This turbine can be turned by water, by gas, or by high temperature steam. The steam turbine is driven by high temperature steam from a conventional boiler reactor or nuclear reactor at speeds averaging 1800 to 3600 rpm. Many of the modern stream turbines operate at temperature in excess of 1,000° F.
Approximately 49 percent of the U.S. power generation in 2003 was coal-fired and 28 percent of the generation from nuclear fuel sources. Both fossil and nuclear steam turbines experience substantial cool down time delays associated with planned major outages, planned minor outages, and unplanned outages. A typical steam turbine requires a minimum of one week to cool down to ambient temperatures using the current methods of shutdown and outage disassembly. This inefficiency represents a substantial amount of lost production and associated revenues for a given generating unit on an annual basis.
Power plant steam turbine metal temperatures cool down at a fairly rapid rate while steam is flowing through the turbine and the generator is connected to the electrical grid. However, most all plant designs include provisions to close the main steam turbine valves when the turbines are removed from service. These design provisions are included for many reasons, one of which is to prevent slugs of water from traveling through the steam turbine and causing damage to the blades and other components. The technical term for this is “turbine water induction” and the American Society of Mechanical Engineers (“ASME”) developed a steam turbine design standard many years ago after turbine water induction failures were reported in the industry.
When steam turbines are removed from service the emergency stop valve and the control valves remain in the closed position. This restricts steam flow through the steam turbine and results in a “bottled up” steam turbine. Typical steam turbines with weights of 125 to 200 tons and operating temperatures of 1000° F. have significant thermal mass. After removing the steam turbines from service, the shell and rotor temperature remains above 700° F. at many locations while the turbine is “bottled” up for many days. Even after one week of conventional cooling down methods, it is not uncommon to measure temperatures in excess of 150° F. on the rotor and thick shell locations.
The prior art fails to provide for a cooling down large steam turbines at electrical generation stations. Steam turbine sizes increased rapidly from 1950 to 1970. During this period, manufactures focused on minimizing rotor stresses and reducing large temperature changes to that result in shell cracking. Moreover, the prior art failed to minimize turbine outages to the extent that commonly exists today. Therefore, there exists a need to cool down steam turbines and to optimize outage time.
The prior art has approached these problems by pre-staging and mobilizing while the turbines are in a cooling down period. Generally, the cool down period in the prior art is concurrent with the disassembly of the steam turbine and occupies the first week of most outages. In recent years the electric utility industry has attempted to reduce the costs associated with turbine outages. The prior art has focused on rapid disassembly and repair techniques while accommodating this cool down period. Therefore, a need exists to improve and optimize outages associated with steam turbines in the electric utility industry that would offer cost incentives associated with electric production including replacement power costs, labor costs, repair costs, and plant operating availability requirements.
There are many factors that attribute to the cool down time of a steam turbine. When turbines are taken off-line or removed from service, electrical breakers are opened, thus removing the generators from the electrical grid. Next, the main steam stop valve and control valves shut automatically to prevent damage due to water induction. The turbine is de-pressurized minutes after shut-down but the steam turbine is in effect “bottled up” as it related to metal temperature. There is no substantial cooling fluid available internally and the turbine cools very slowly as heat escapes only through the shell and outer insulation. After a steam turbine is removed from the grid, the turbine is allowed to spin freely from its nominal operating speed down to approximately 90 rpm in twenty to thirty minutes.
During the spin-down there is usually only minimal steam flow in the reverse direction through the high pressure turbine to prevent excessive temperatures due to steam stagnation. The lube oil system remains in operation while the “hot” turbine is on turning gear until the first stage metal temperature reaches approximately 500° F. This takes approximately 40 to 80 hours depending on the turbine. At this time the oil system can be taken offline and the turbine can be completely disassembled. The initial outer and inner shells are often removed with some component temperatures at several hundred degrees Fahrenheit. The turbine rotor usually is removed and placed on the stands near the turbine with internal temperatures exceeding 150° F. Most high pressure turbine rotors are not physically removed from the inner shell casing until five to eight days after the unit is taken off-line.
Though there is no consistent method of turbine disassembly, the turbine is disassembled hot and cooling occurs after disassembly in the prior art. The current practices are followed to reduce the metal temperatures without damage to the turbine. In the prior art, cooling down the turbine assembly can only occur as long as steam flows through the turbine.
Because these methods require workers to disassemble the turbine prior to the cool down process, cool down the turbine and disassembly may occur at temperatures between 200 and 500° F. The rate of turbine cool down depends on the willingness of workers to work on hot components, safety concerns, rigging limitations, and insulation removal activities. On large steam turbines, meaningful turbine cooling of the shell is usually not achieved until the crossover pipe between the high pressure turbine section and/or intermediate pressure turbine sections and the low pressure turbine section is removed. This is usually not attempted until the turbine's metal temperatures are less than 600° F. Once the crossover pipe is removed, the rate of cooling due to air convection increases dramatically. In summary, this method does not provide reasonable, efficient, or adequate cooling for outage and cost optimization.
The prior art offers two methods to improve the cooling time associated with large steam turbines. The primary method of reducing the cool down time is to force cool the turbine components prior to bringing the turbine off-line. This typically consists of reducing the main steam temperature just prior to removing the steam turbine from service. The main steam temperature is reduced by closing the extraction steam sources to the feedwater heaters, reducing steam temperature through attemperation, and slowly lowering the steam temperature to near saturation temperatures. This forced cool down method is expected to be used on 400 megawatt and larger units.
Though this method of forced cool down removes a substantial amount of heat from the steam turbine, the saturation temperature limitations and potential for water induction fails to provide for a substantial cool down of the steam turbine. This method only cools the turbine down from over 1000° F. to temperatures between 700-900° F. in the high pressure turbine section of the turbine. This only saves about one to about one and one half days in the unit's outage shutdown.
Moreover, this method offers the additional problem that even after this forced cool down, the operator cannot shut off the lubrication system on the turbine and the operator cannot disassemble the turbine until the metal temperatures are between 500-600° F. Furthermore, there is a significant hazard with disassembling the turbine at this high temperature.
In addition, using this cool down method while the unit is still in service may fail because the turbine operations will trip for several reasons. Therefore, this method of forced cool down is unable to offer an efficient method of cooling down the turbine to allow maintenance of the turbine. Moreover, the calibration of station instrumentation, the condition of level detection devices, the inadequate operational staff during shutdown, the system power levels and load changes, the boiler tuning, and the other plant configuration matters will further limit the usefulness of this method.
The second method of the prior art is air cooling. Various air horns are placed at limited internal access points throughout the turbine. This method does not provide efficient cool down of the turbine because air at near ambient pressure does not provide enough heat transport and non-uniform distribution of cooling. This method results in humping, which is stagnant steam distributing in large turning shells in a manner that stratifies the steam and results in convective heating that is cooler on the bottom and warmer on the top. This problem occurs when the turbine is “bottled up” with hot steam and the metal is slightly longer at the top of the shell than at the bottom of the shell. This misalignment can cause rotor contact.
This method is also deficient because of limited accessibility, limited compressed air capacity, and non-uniform distribution of cooling throughout the turbine. These three factors result in not only a lack of cooling capacity but problems with shell humping and non-uniform component cooling. Moreover, two limitations of forced cooling using air injection are adequate cooling capacity and uniform cooling. This method has only been shown to save minimal time in the shut down of steam turbines.
The electric utility industry has experienced dramatic changes over the past two decades and continues to encounter significant competitive changes associated with the generation of electricity. These competitive changes are a driving force to produce electricity more efficiently and cost effectively. Electric utility power plant outages are an integral part of the electric power industry and therefore are a critical component in evaluating electrical demand and the ability to satisfy the demand through generation resource allocation.
These outages consist of both planned and unplanned events that have variable time durations depending on various factors. The cost consequences of outages is highest during summer and winter peak power demand periods, whereas outage costs during other time periods are more predictable. Other factors that influence outage consequences include reduced electric capacity, power plant age, wholesale market price and volatility, environmental regulations, electric deregulation, and other factors. With respect to power plant age, it is noted that the average age of most of the large power plants in the U.S. is over 30 years which emphasizes the importance of regular scheduled maintenance outages which in turn requires time and money. Therefore, a need exists to minimize the costs associated with an outage by reducing the amount of time needed to service the turbines.
Flows of nitrogen have been used in different arts, but this technology has not been implemented on devices with internal moving parts. In the chemical, petrochemical and oil refining industry, various reactor vessels that operate at 1,000° F. are taken off line for maintenance. These processes are used to reduce crude oil to useable end products. These large reactor vessels contain various catalysts that aid the crude processing. These catalysts become spent and are required to be periodically replaced. The reactor vessels are cooled down from their operating temperatures over 600° F. to less than 100° F. The process equipment being cooled in this art are reactor vessels that are stationary and static with no moving parts. Care must be taken to not cool the metal to fast, which can cause metal fatigue and cracking from stresses caused from shocking the metal. For vessels with no moving parts, liquid nitrogen has been forced through vessels having metal surfaces at greater than 350° F. Most metal can be cooled down at rates of 75-100° F. per hour.
In the early 1980s, Union Carbide Industrial Services used liquid nitrogen to cool down reactor vessels instead of recycling process nitrogen and hydrogen gases through the units compressor systems. In operation, the plant systems allowed recycling the gas through the reactor to absorb heat, and then passing that gas through the system's heat exchangers to cool the gas. The compressors pumped the gas back through the reactor to force cooling. This required four to six days to obtain temperatures below 100° F.
In contrast, a steam turbine operates under very dramatic conditions with a large spindle spinning at 3600 rpm inside a stationary shell. The heat shrinkage of the stationary shell to the spindle and the stationary shell to the spindle blades of the turbine is a factor. If the cooling is not completed with careful control so that all parts of the machinery cool at the same rate, damage can occur to the machine with spinning parts coming into contact with stationary parts, humping can occur, and the weight of the turbine can shift from one end to the other too fast, thus causing damage. Therefore, a need exists to provide for a cool down of a turbine with moving internal parts such that the cool down rate may be controlled.
The purpose of cooling and shutting down a turbine is often due to a decline in performance due to deposits on the turbine blades. This may be recognized by the operator due to a gradual loss of power production by the machine and increased fuel consumption.
The deposits on the blades can be a range of contamination products, depending on, for example, the fuel gas and air intake filtration capabilities for gas turbines, and the steam impurity content for steam turbines. These deposits can include dirt or soil, copper oxide, sand, coal dust, insects, salt oil, turbine exhaust gas and combustion deposits such as sulfur oxide. Some of these contaminates are corrosive to the turbine, while oily hydrocarbon type deposits that form on gas turbines increase the ability of other contaminants to cling to the turbine parts. Removal of this oily glue substance can aid in the production recovery of the gas turbine.
Gas turbine deposits are often the result of the combustion of natural gas or flue gas from an up stream coal combustion process that can be used to power the turbine. The operation leaves sulfur residues, thought to be sulfur dioxide deposits, on the gas turbine blades that can become corrosive and in extreme cases, and can cause imbalance in the turbine and excessive vibrations. The prudent gas turbine owner, periodically completes a wash of the turbine blades to remove these sulfur dioxide deposits. Other types of turbines can also periodically be cleaned. For example, steam turbines are sometimes cleaned to remove copper oxide deposits that occur due to copper carried in the production steam/water vapor.
There are two common practices in the power industry to clean turbine blades. One method, mechanical cleaning by grit blasting after the turbine is disassembled, can be employed on both steam turbines and gas turbines. The cleaning media for grit blasting can include uncooked rice or ground up nut shells. However, because this method involves disassembly of the turbine, it can be a time consuming and costly process.
Another turbine cleaning option is the injection of rice or nut shells into the turbine while it is operating at a reduced load. This process is usually carried out after the water washing practice.
The second common method for cleaning turbine blades involves a liquid cleaning process using micro-emulsion water based detergents. The cleaning agent used can depend on the type of deposits being removed and is often pre-approved by the turbine manufacturer. Specifically with respect to gas turbine cleaning, there are several emulsion based cleaners that are well known in the art for washing gas turbine blades.
During the turbine washing process, the turbine can be partially or completely de-energized (e.g., the turbine is taken offline and the turbine blades are allowed to turn largely by inertia as opposed to being driven by forced steam or air; although a mechanical means, such as a turning gear off base air compressor drive, can sometimes be used to keep the bearings lubricated, as is well known in the art). The cleaning solution can be, for example, a 5-10% cleaning agent mixed with clean water. An issue in these applications is water quality and purity. Water quality should be, for example, less than 100 ppm dissolved solids, less than 10 ppm chlorides, less than 25 ppm sodium and a pH of 6-8. Poor water quality leads to more inorganic deposits on the turbine blades, chloride stress corrosion occurring on turbine parts and shortened turbine life.
The cleaning solution can be applied by using either a permanent spray system or a hand held spray system. The chemical spraying can be completed with the machine on turbine gear or crank speed. To prevent thermo shock, the main turbine shaft temperature can be under 200° F. using ambient (50°-80° F.) water. If using 150°-200° F. water, the main turbine shaft temperature can be under 300° F.
The contact time of the cleaning solution with the turbine can depend on the amount of debris to be removed. Once it has been determined that the system is clean, a water rinse (e.g., substantially pure water) can be added to wash off remaining cleaning solution.
In another field of technology, the practice of injecting small amount of atomized cleaning compounds into saturated steam has been used for several years to chemically clean piping. Most of these applications were used for the cleaning of oxygen or fuel gas piping for the removal of preservatives and iron oxides using water based mild alkaline and weak acidic solution. These applications were completed to clean the interior pipe walls, but are not known for use with turbines. Using an alternate gas in place of steam, such as nitrogen, was not attempted because of the type of cleaning compounds used and the readily available steam supply.
That steam based chemistry of the above process depends heavily on dissolution of the contamination on the pipe walls by the water solution. Examples of well known water cleaning agents include alkalines, which can be used for degreasing the pipe walls, and citric and EDTA acids, which can be used to dissolve iron oxide deposits. These water based cleaning methods are heavily dependent on the water droplets in the saturated steam to carry and disburse the cleaning compounds. One reason that nitrogen was not previously used in this cleaning process was because it is a dry gas and can be relatively expensive compared to readily available saturated steam.
Similar aerosol techniques have been used for many different purposes, such as die lubrication, spray coatings, moisturizing, humidification, flue gas conditions, dust control and for removing hydrocarbon vapors after shutdown of oil or gas refineries. In one such process, a hydrocarbon refinery has been purged with nitrogen gas, then purged with steam, where cleaning compounds were added as an aerosol to the steam in order to aid in encapsulating hydrocarbons.